# IGCC Plant — Bituminous Coal GE Energy IGCC 

# GE Energy IGCC Plant

Plant Overview This analysis is based on a 640 MWe (net power output) Integrated Gasi fi cation Combined-Cycle (IGCC) plant using GE Energy (GEE) radiant-only gasi fi cation technology, located at a green fi eld site in the midwestern United States. The radiant-only
con fi guration consists of a radiant synthesis gas cooler followed by a water quench. Two pressurized, slurry-fed, entrained fl ow gasi fi cation trains feed two advanced F-Class combustion turbines. Two heat recovery steam generators (HRSGs) and one steam turbine provide additional power. The combination process and heat and mass balance diagram for the GEE IGCC plant is shown in Figure 1. The primary fuel is an Illinois No. 6 bituminous coal with a higher heating value (HHV) of 11,666 Btu/lb. The capacity factor (CF) for the plant is 80 percent without sparing of major train components. A summary of plant performance data for the GEE IGCC plant is presented in Table 1.

Figure 1. Process Flow Diagram GEE IGCC Table 1. Plant Performance Summary Plant Type GEE IGCC Carbon capture No Net power output (kWe) 640,250 Net plant HHV ef fi ciency (%) 38.2 Primary fuel (type) Illinois No. 6 coal Levelized cost-of-electricity(mills/kWh) @ 80% capacity factor 78.0

Note: Diagram is provided for general reference of major fl ows only. For complete fl ow information, please refer to the fi nal report.

# IGCC Plant — Bituminous Coal GE Energy IGCC

B_IG_GEE–2 

## Technical Description The plant uses an improved version of the GEE gasi fi cation technology (formerly licensed by Chevron Corp. and predecessor company Texaco Inc.), which is currently in operation at the 250 MWe Tampa Electric IGCC plant in Polk County, FL. All technology selected in the plant design is assumed to be available to facilitate a 2010 startup date for anewly constructed plant. A summary of performance for an advanced F-Class combustion turbine for the GEE IGCC plant is presented in Table 2. Two gasi fi cation trains process a total of 5,876 tons of coal per day. A slurry (63 percent by weight coal) is transferred from the slurry storage tank to the gasi fi er with a high-pressure pump. Oxygen (O 2 ) is produced in a cryogenic air separation unit. The coal slurry and O 2react in the gasi fi er at about 5.6 MPa (815 psia) at a high temperature (in excess of 1,316°C [2,400°F]) to produce syngas. Hot syngas and molten solids from the reactor fl ow downward into a radiant heat exchanger, where the syngas is cooled to 593°C (1,100°F) and the ash solidi fi es. Raw syngas continues downward into a quench system where most of the particulate matter (PM) is removed and then into the syngas scrubber where most of the remaining entrained solids are removed along with ammonia. Slag captured by the quench system is recovered in a slag recovery unit. The gas goes through a series of additional gas coolers and cleanup processes, including a carbonyl sul fi de hydrolysis reactor, a carbon bed for mercury (Hg) removal, and a Selexol-based acid gas removal (AGR) plant. A Brayton cycle, fueled by syngas, is used in conjunction with a conventional subcritical steam Rankine cycle for combined-cycle power generation. Compressed nitrogen from the air separation unit is used for syngas dilution, which aids in minimizing the formation of nitrogen oxides (NOx) during combustion in the gas turbine burner section. The limiting factor that determines the use of a subcritical steam cycle is the maximum design pressure of 12.4 MPa (1,800 psig), which can be tolerated in the GEE radiant cooler. The two cycles are integrated by generation of steam in the HRSGs, by feedwater heating in the HRSGs, and by heat recovery from the IGCC process (radiant syngas cooler). The HRSG/steam turbine cycle is 12.4 MPa/566°C/566°C (1,800 psig/1,050°F/1,050°F). The plant produces a net output of 640 MWe. The summary of plant electrical generation performance is presented in Table 3. This con fi guration results in a net plant ef fi ciency of 38.2 percent (HHV basis), or a net HHV heat rate of 8,922 Btu/kWh. 

## Environmental Performance The environmental speci fi cations for a green fi eld IGCC plant are based on the Electric Power Research Institute CoalFleet User Design Basis for Coal-Based IGCC Plantsspeci fi cation. Low sulfur dioxide (SO 2 ) emissions (less than 4 ppmv in the fl ue gas) are achieved by capture of the sulfur in the Selexol AGR process, which removes over 99 percent of the sulfur in the fuel gas. The resulting hydrogen sul fi de-rich regeneration gas from the AGR system is fed to a Claus plant, producing elemental sulfur. Nitrogen oxides emissions are limited by nitrogen dilution in the gas turbine combustor to 15 ppmvd (as nitrogen oxide at 15 percent O 2 ). Filterable PM dischargeto the atmosphere is limited by the use of the syngas quench in addition to the syngas scrubber and the gaswashing effect of the AGR absorber. Ninety- fi ve percent of the Hg is captured from the syngas by an activated carbon bed. Table 2. Advanced Gas Turbine Performance 1 Advanced F-Class Net output, MWe 185 Pressure ratio 18.5 Airfl ow, kg/s (lb/s) 431 (950) Firing temperature°C (°F) >1,371 (>2,500)

1 At International Standards Organization conditions fi ring natural gas. Performance information for syngas fi ring is not available.

Table 3. Plant Electrical Generation Electrical Summary Advanced gas turbine x 2, MWe 464.3 Steam turbine, MWe 298.9 Sweet gas expander, MWe 7.1 Gross power output, MWe 770.3 Auxiliary power requirement, MWe (130.1) Net power output, MWe 640.2

# IGCC Plant — Bituminous Coal GE Energy IGCC

B_IG_GEE–3 A summary of the resulting air emissions for the GEE IGCC plant is presented in Table 4. 

## Cost Estimation Plant size, primary/secondary fuel type, construction time, total plant cost (TPC) basis year, plant CF, plant heat rate, fuel cost, plant book life, and plant in-service date were used to develop capital cost, production cost, and levelized cost-of-electricity (LCOE) estimates. Costs for the plant were based on adjusted vendor-furnished and actual cost data from recent design/build projects. Values for fi nancial assumptions and a cost summary are shown in Table 5. Project contingencies were added to each case to cover project uncertainty and the cost of any additional equipment that could result from detailed design. The project contingencies represent costs that are expected to occur. Project contingency was 13.3 percent of the GEE IGCC case TPC. Process contingency is intended to compensate for uncertainties arising as a result of the state of technology development. Process contingencies represent 2.5 percent of the GEE IGCC case TPC and have been applied to the estimates as follows: Slurry Prep and Feed – 5 percent on GE IGCC cases. Gasi fi ers and Syngas Coolers – 15 percent on all IGCC
cases. Mercury Removal – 5 percent on all IGCC cases. Combustion Turbine Generator – 5 percent on all IGCC cases without CCS. Instrumentation and Controls – 5 percent on all IGCC cases. This study assumes that each new plant would be dispatched any time it is available and would be capable of generating maximum capacity when online. Therefore, CF is assumed to equal availability and is 80 percent for IGCC cases. The 640 MWe (net) GEE IGCC plant was projected to have a TPC of $1,813/kWe, resulting in a 20-year LCOE of 78 mills/kWh. •

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• Table 4. Air Emissions Summary @ 80% Capacity Factor Pollutant GEE IGCC Without

CSS CO 2 • tons/year 3,937,728 • lb/MMBtu 197 • cost of CO 2avoided N/A SO 2 • tons/year 254 • lb/MMBtu 0.0127 NOx • tons/year 1,096 • lb/MMBtu 0.055 PM (fi lterable) • tons/year 142 • lb/MMBtu 0.0071 Hg • tons/year 0.011 • lb/TBtu 0.571

# IGCC Plant — Bituminous Coal GE Energy IGCC

B_IG_GEE–4 Reference: Cost and Performance Baseline for Fossil Energy Plants, Vol. 1, DOE/NETL-2007/1281, May 2007. B_IG_GEE_051507 Julianne M. Klara Senior Analyst National Energy Technology Laboratory 626 Cochrans Mill Road P.O. Box 10940 Pittsburgh, PA 15236 412-386-6089 julianne.klara@netl.doe.gov John G. Wimer Systems Analysis Team Lead National Energy Technology Laboratory 3610 Collins Ferry Road P. O. Box 880 Morgantown, WV 26507 304-285-4124 john.wimer@netl.doe.gov 

## Contacts Table 5. Major Financial Assumptions and Resulting Cost Summary 1 Major Assumptions

Case: 1x640 MWe net GEE IGCC Plant Size: 640.3 (MWe, net) Heat Rate: 8,922 (Btu/kWh) Primary/Secondary Fuel (type): Illinois #6 Coal Fuel Cost: 1.80 ($/MMBtu) Construction Duration: 3 (years) Plant Life: 30 (years) Total Plant Cost 2Year: 2007 (January) Plant in Service: 2010 (January) Capacity Factor: 80 (%) Capital Charge Factor: 17.5 (%) Resulting Capital Investment (Levelized 2007 dollars) Mills/kWh Total Plant Cost 43.3 Resulting Operating Costs (Levelized 2007 dollars) 3 Mills/kWh Fixed Operating Cost 5.8 Variable Operating Cost 7.5 Resulting Fuel Cost (Levelized 2007 dollars) @ $1.80 / MMBtu Mills/kWh 19.4 Total Levelized Busbar Cost of Power (2007 dollars) Mills/kWh 78.0

1 Costs shown can vary ± 30%.

2 Total plant cost includes all equipment (complete with initial chemical and catalyst loadings), materials, labor (direct and in direct), engineering and construction management, and contingencies (process and project). Owner’s costs are not included.

3 No credit taken for by-product sales.